Method of designing and executing a well treatment

ABSTRACT

An apparatus and a method for treating a subterranean formation comprising designing a treatment that comprises a composition, wherein the design comprises a pressure influence on a viscosity of the composition, and performing the treatment, wherein the composition is not an energized fluid. An apparatus and a method wherein the viscosity is at least partially estimated based on experimental rheological data collected at pressures below about 500 psi and/or at a pressure that is about 1 atm to about 2,000 atm. 
     An apparatus and a method for exposing a subterranean formation to a composition, comprising forming a composition comprising a polymer and a crosslinker, and pumping the composition into the subterranean formation, wherein the forming the composition comprises selecting the composition components in response to a pressure and temperature of the subterranean formation and experimentally derived behavior of the polymer and the crosslinker at the pressure, temperature, and pH of the subterranean formation. A method wherein the experimentally derived behavior of the polymer and the crosslinker is at least partially estimated based on experimental data at the pressure and temperature of the subterranean formation and/or wherein the pressure experienced by the composition being pumped into the subterranean formation is above 65 atm.

RELATED APPLICATION DATA

This application claims priority as a continuation in part application of U.S. patent application Ser. No. 11/625,105 which claims priority to U.S. Provisional Patent Application Ser. No. 60/761,550, filed Jan. 24, 2006, both of which are hereby incorporated by reference herein.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

This invention relates to the techniques used for stimulating hydrocarbon-bearing formations—i.e., to increase the production of oil/gas from the formation and more particularly, to a process for optimizing fluids for and monitoring fluid rheological performance during fracture stimulation treatments.

Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation and thus causing a pressure gradient that forces the fluid to flow from the reservoir to the well. Often, a well production is limited by poor permeability either due to naturally tight formations or due to formation damages typically arising from prior well treatment, such as drilling, cleaning etc.

To increase the net permeability of a reservoir, it is common to perform a well stimulation. A common stimulation technique is hydraulically fracturing a formation penetrated by a wellbore. Hydraulic fracturing typically consists of pumping a proppant-free viscous fluid, or pad, usually water with some fluid additives to generate high viscosity, into a well faster than the fluid can escape into the formation so that the pressure rises and the rock breaks, creating artificial fractures and/or enlarging existing fractures. Then, proppant particles are added to the fluid to form a slurry that is pumped into the fracture to prevent it from closing when the pumping pressure is released. The proppant suspension and transport ability of the treatment base fluid depends on the type and concentration of viscosifying agent added.

Fracturing technology relies on fluids that exhibit flow behavior that changes over the course of a fracturing treatment. A fracturing fluid must be viscous enough to carry the proppant through the perforations and through the fracture, and to minimize fluid loss to the formation. On the other hand, the fluid should ideally be thinner in the tubing to limit horsepower requirements and to minimize shear degradation. To facilitate an efficient clean-up, its viscosity must be reduced to an absolute minimum after the treatment is over, thus ensuring optimum fracture conductivity and well productivity. A single fluid can meet all of these requirements, but a successful fracturing treatment requires a careful fluid design. That is, the fluid composition should be chosen based on formation temperature and pressure, pumping rate, pumping time, completion capacity, water quality, etc. The fluid design for a fracturing treatment is traditionally determined based on both experience and laboratory testing, whereas modeling has previously only played a minor role or no role at all. Fracturing fluid designs, fluid compositions, and breaker schedules for a fracturing job are often tailored based on lab rheology measurements and/or experience. Models are not solely used in the determination of the gel loading, crosslinker concentration, breaker schedule, etc. In some instances, fracturing simulators employing simple models such as the power law model and the Cross model are used to represent the fluid rheology. These models are regressed to the rheology data for the actual fluid being pumped, so experimental data is needed. None of these models account for the live chemistry of fracturing fluids, i.e., the fact that crosslinks are dynamically formed and broken, as well as polymer linkages that are broken by thermal degradation or degradation by oxidizers.

Borate crosslinked polymer gels have been used in subterranean applications for more than 30 years. They offer certain advantages over polymer gels crosslinked with group 4 transition metals such as titanium and zirconium. A key advantage is that they are shear reversible. That is, when the crosslinked gel is placed under shear, the number of active crosslinks are reduced, resulting in a thinner fluid. This less viscous fluid moves with less friction at high rates through tubing and casing, requiring less hydraulic horsepower in the operation. When shear rates are reduced, as, for example, when the fluid moves from the tubular into the hydraulically-induced fracture, the number of crosslinks increases and viscosity is recovered.

It is intuitive to expect that for incompressible fluid systems (excluding the behavior of energized and foamed fluids, which are significantly affected by pressure as expected due to the compressible gas phase) that increasing hydrostatic pressure would have minimal or no impact on the measured viscosity, and that if there were some impact, it would tend to increase the viscosity. However, this is not what has been observed.

It has been found that hydrostatic pressure (also known as isostatic pressure) on a borate-crosslinked polymer gel can influence viscosity. This effect has been confirmed in a number of rheometers and in high pressure view cells. High pressure 11B NMR measurements have also confirmed that when a borate-crosslinked polymer gel is placed under pressure, the uncomplexed, or “free borate” increases with increasing pressure with a concomitant decrease of the chemically bound borate.

Therefore, a need exists for methods that can more accurately predict viscosity of borate-crosslinked polymer gel at high pressure to reduce the number of laboratory experiments needed, to improve models of the gel behavior, and to facilitate more accurate real-time QA/QC of fracturing fluids, so that the treatment may be adjusted if needed.

SUMMARY

Embodiments of the invention relate to an apparatus and a method for treating a subterranean formation comprising designing a treatment that comprises a composition, wherein the design comprises a pressure influence on a viscosity of the composition, and performing the treatment, wherein the composition is not an energized fluid. Embodiments of the invention relate to a viscosity that is at least partially estimated based on experimental rheological data collected at pressures below about 500 psi and/or at a pressure that is about 1 atm to about 2,000 atm.

Embodiments of the invention relate to an apparatus and a method for exposing a subterranean formation to a composition, comprising forming a composition comprising a polymer and a crosslinker, and pumping the composition into the subterranean formation, wherein the forming the composition comprises selecting the composition components in response to a pressure and temperature of the subterranean formation and experimentally derived behavior of the polymer and the crosslinker at the pressure, temperature, and pH of the subterranean formation. Embodiments of the invention relate to a method wherein the experimentally derived behavior of the polymer and the crosslinker is at least partially estimated based on experimental data at the pressure and temperature of the subterranean formation and/or wherein the pressure experienced by the composition being pumped into the subterranean formation is above 65 atm.

Embodiments of the invention relate to an apparatus and a method for exposing a subterranean formation to a composition, comprising forming a composition comprising a polymer and a crosslinker, pumping the composition into the subterranean formation, wherein the composition viscosity is estimated using the following formula,

${{Vis}\; {{cosity}({cP})}} = \frac{47\text{,}880k_{a}^{\prime}}{\gamma^{({1 - n^{\prime}})}}$

wherein γ is the shear stress, and k_(a)′ and/or n′ is a function of pressure, and wherein the forming the liquid comprises using the estimated composition viscosity.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention may be understood by reference to the following description taken in conjunction with the accompanying drawings.

FIG. 1 provides a plot of boric acid/borate anion equilibrium as a function of pH at varied temperature.

FIG. 2 provides an example of the thermoreversibility of a borate-crosslinked gel.

FIG. 3 provides a plot of actual versus predicted melt temperatures for a range of boron crosslinked polymer.

FIG. 4 is a plot of experimental viscosity as a function of time at varied temperature and pressure for an embodiment of the invention.

FIG. 5 is a plot of calculated and experimental viscosity as a function of time at varied temperature and pressure for an additional embodiment of the invention.

FIG. 6 is a plot of calculated and experimental viscosity as a function of time at varied temperature and pressure for an additional embodiment of the invention.

FIG. 7 is a three dimensional plot of calculated viscosity at varying conditions of temperature and pressure of a fluid comprising 0.36% wt guar crosslinked with 60 ppm boron at pH 8.8.

DETAILED DESCRIPTION OF THE INVENTION

Formation and downhole pressure and temperature can have an impact on fluid rheology. In the case of pressure, when there is adequate pressure present in the treatment or delivery environment, the effective crosslinking functionality of a crosslinking agent, such as a borate, may be significantly reduced. Such pressures are those on the order of magnitude of 10³ psi or greater, such as 4×10³ psi or greater. For example, at 4×10³ psi, measured viscosity of a borate crosslinked fluid can be less than half of the viscosity of that measured at 500 psi. Thus, the pressure affects on a borate crosslinked fluid can be taken into account in some embodiments of the invention.

The method for calculating the effect of pressure upon borate-crosslinked gels employs five (5) parameters to describe the gels' rheology. These parameters are pressure, temperature, crosslinker (boron) concentration, pH and polymer concentration.

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

The description and examples are presented solely for the purpose of illustrating the preferred embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. While the compositions used in methods of the invention may be described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than those cited. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range.

Several terms used in this detailed description are common, and a brief discussion of some of the terms is provided simply for clarity. Incorporating crosslinkers into a fluid further augments the viscosity of a treatment fluid that contains polymer. Crosslinking consists of the attachment of two polymeric chains through the chemical association of such chains to a common element or chemical group, whereas such element or group is referred to as the crosslinker. Typical crosslinkers are polyvalent metal ions, more often zirconium or titanium ions or borate ions. Crosslinking is very sensitive to the prevailing pH. For example, crosslinking with borate ions can be performed only in alkaline media (pH>7). pH-regulating systems (“buffers”) are often required to achieve effective crosslinking with metal ions.

As used herein, the word “crosslinked” means a polymer/crosslinker system which has effectively developed viscosity higher than that of the polymer alone, unless indicated otherwise or clear from the context within which the term is used. Unless otherwise indicated, the term “treatment scenario” means the fluid formulation and treatment schedule for the fluid as used to treat a subterranean formation. The term “rheology” in the broadest sense of the term, that part of mechanics which deals with the relation between force and deformation in material bodies. The nature of this relation depends on the material of which the body is constituted. It is customary to represent the deformation behavior of fluids by the model of the linear viscous or Newtonian fluid (displaying the property known as viscosity). These classical models are, however, inadequate to depict certain nonlinear and time-dependent deformation behavior that is sometimes observed. It is these nonclassical behaviors which are referred to as rheological behavior, or rheology. Rheological behavior is particularly readily observed in materials containing polymer molecules which typically contain thousands of atoms per molecule.

“Subterranean formation treatments” include, but are not limited to, fracturing, acidizing, wellbore cleanout, gravel packing, acid diversion, fluid loss control, and the like. Subterranean formation treatments also include a wellbore penetrating the formation, and include such methods as treatment fluid design, breaker schedule design, rheology representation in treatment simulators, and even real-time QA/QC of treatment fluid rheology. Preferably, the embodiments of the invention are fracturing methods which include design of the fracturing fluid, design of the fracturing treatment, injection of the fracturing fluid into the wellbore, stimulating the formation, and monitoring/optimizing the fluid/treatment based upon real-time monitoring.

Foamed and energized fracturing fluids are generally described by their foam quality, i.e. the ratio of gas volume to the foam volume. If the foam quality is between 52% and 95%, the fluid is conventionally called foam, and below 52%, an energized fluid. Any suitable gas that forms a foam or an energized fluid when introduced into the aqueous medium can be used, see, for example, U.S. Pat. No. 3,937,283 (Blauer et al.). The gas component may comprise a gas selected from the group consisting of nitrogen, air, carbon dioxide and any mixtures thereof. The gas component may comprise nitrogen, in any quality readily available. The fluid may contain from about 10% to about 90% volume gas component based upon total fluid volume percent. In this application, an “energized fluid” is a foam or energized fluid composition that contains 10 percent or more volume gas component based upon total fluid volume percent.

Embodiments of this invention relate to the techniques used for treating hydrocarbon-bearing formations—such as to increase the production of oil/gas from the formation and more particularly, to a process for treating a subterranean formation by optimizing fluids for and monitoring fluid placement during treatment. A method of calculating the impact of the in situ conditions of pressure and temperature on the fluid retained viscosity has been developed. This method is particularly advantageous, since it is applied to and adjusts rheology values measured using industry standard techniques and instrumentation defined in ISO-13503-1 (Ref: ISO-13503-1 Petroleum and Natural Gas Industries—Completion Fluids and Materials Part 1: Measurement of viscous properties of completion fluids). This advantage is particularly useful because it removes the necessity of making numerous rheology measurements on expensive, high-pressure instruments that are not widely available.

Methods of the invention employ a rheology model that describes the chemical reactions that occur in a crosslinked viscosifying agent based treatment fluid. One example of such a fluid is a borate-crosslinked guar-based fracturing fluid. A model for predicting the change in viscosity of a borate crosslinked fluid system due to the influence of hydrostatic pressure has been developed. The prediction is semi-empirical and has been found to be applicable for all of the typical borate crosslinked guar-based polymer fluid systems routinely employed in operations where the fluid is pumped into subterranean formations as part of operations in the oil and gas industry.

Initially, a discussion of the chemistry is helpful. It is generally accepted that the boron species involved in crosslinking is the monoborate anion B(OH)₄ ⁻. This ion is in equilibrium with boric acid in dilute aqueous systems, defined by the equation:

H₃BO₃+OH⁻=B(OH)₄ ⁻

Because boric acid is a weak Lewis acid, with a pKa of about 9.2, the above equation can also be written as

H₃BO₃+H₂O=B(OH)₄ ⁻+H⁺

It can be seen from the above equations that pH will influence the amount of borate anion available for crosslinking. Also, since pH in aqueous systems is strongly influenced by temperature, the equilibrium in the above equations will be shifted to the left as temperature is raised.

FIG. 1 shows the fraction of the total boron that is converted to the borate anion crosslinking species. From this, it is also clear that under a given condition of pH and temperature, an increased total concentration of boric acid will produce a correspondingly higher concentration of the borate anion. These facts support using pH, temperature and crosslinker concentration in a relatively simple model.

In one embodiment, the chemistry of viscosity-increasing borate-crosslinked guar-based fluids is represented by a simple model that considers the crosslinking-related reactions to be at equilibrium. The key constituents are assumed to be H⁺, OH⁻, boric acid B(OH)₃, borate B(OH)₄ ⁻, crosslink sites located on the separate polymer molecules G_(x) and Gy and connections between crosslink sites formed by borate (crosslinks) G_(x)B⁻G_(y)

In a similar manner to the shear reversibility described above, borate-crosslinked gels are thermally reversible. When heated, a crosslinked gel will lose viscosity gradually and successively as the temperature is increased, and at a certain temperature it will show a precipitous or catastrophic loss of viscosity. This temperature is termed the “melt” temperature. Upon lowering the temperature, the viscosity of the gel will recover to previous values. Of course, this recovery can be compromised or completely lost if the temperature is held high enough and long enough to thermally degrade the polymer itself.

Melt temperatures can be determined easily in standard rheometers defined for use in the industry under ISO-13503-1 at pressures ranging up to about 35 bars. An example of polymer melt temperature determination is shown in FIG. 2. These melt temperatures have been found to be very reproducible for a composition, and very predictable based upon fluid compositions useful in the industry. This melt temperature consistency was found to hold for compositions, regardless of the source of the boron. For example, primary sources of boron for crosslinkers in the industry are boric acid, borax, and other boron-containing alkaline earth minerals, such as ulexite and colemanite.

FIG. 3 shows the agreement with an equation which contains temperature, boron concentration, pH and polymer loading.

It can be seen that polymer melt temperature alone provides a maximum temperature boundary for the fluid, above which, there is no contribution of viscosity from crosslinking. While this temperature is of interest, and is useful data for simulating the behavior of the fracturing operation, it is only a boundary or limiting condition, and when determined using standard rheometers, does not incorporate the influence of high pressure upon the fluid viscosity.

Understanding the fluid system rheological performance under the different wellbore and reservoir conditions is critical in order to design a pumping schedule that will have the best chance of meeting the overall objectives for the treatment. The industry-accepted practice for determining rheological properties for these treatments are described in ISO-13503-1 (Ref: ISO-13503-1 Petroleum and Natural Gas Industries—Completion Fluids and Materials—Part 1: Measurement of viscous properties of completion fluids). The only guideline for pressure during the test in this standard is for preventing the fluid from reaching its boiling point when being tested at higher temperatures, which may affect the measurement and potentially damage the instrument. A semi-empirical predictive algorithm is used to predict the performance of the viscosity of the system as a function of the applied pressure without having to run a specific test each time with a high pressure, high temperature (HPHT) rheometer. This is important to understand the effect because often during the treatment the pressure varies from what was predicted and real-time decisions will need to be made as to take taken in order to account for the change in fluid system properties so that the objectives of the treatment can be met.

The adjustment made to the viscosity due to the change in pressure is an offset of the original viscosity profile of the fluid measured at standard pressure conditions as outlined in the ISO specification. There may also be a change in the non-Newtonian behavior of the fluid over the range of shear rates the fluid might experience over the course of the treatment. Fracturing fluids are characterized by the Power-Law model in which n′ is the behavior index and k′ the consistency index. The equation for calculating viscosity (in cP) as a function of shear rate, k′, and n′ is as follows.

${{Viscosity}({cP})} = \frac{47\text{,}880k^{\prime}}{\gamma^{({1 - n^{\prime \;}})}}$

where γ is shear rate in sec⁻¹ and k′ is in units of (lbf-ŝn′/ft̂2).

In some regimes, k′ is modified to adjust the estimate provided by the Power Law equation. That is, the viscosity should be calculated using the following.

${{Viscosity}({cP})} = \frac{47\text{,}880k_{a}^{\prime}}{\gamma^{({1 - n^{\prime}})}}$

Where k_(a)′ is at the k′ measured at the conditions of temperature and low pressures used in rheometers defined in ISO-13503-1 and adjusted for pressure. As the pressure the gel is exposed to is increased, there will be a threshold pressure at which k_(a)′ begins to decrease. Raising the pressure further will cause a further decrease in k_(a)′. This effect seems to result in viscosities that approach those which would have resulted from only the uncrosslinked fluid at the same temperature. That is, a pressure may be applied where there is no remaining viscosity contribution from the crosslinker.

In some embodiments, as the pressure increases, n′ increases. n′ may have a value of 1 over some regimes. In some embodiments, experimental rheological data is collected at pressures below about 500 psi or at a pressure that is about 1 atm to about 2,000 atm. In some embodiments, the pressure influence occurs at a pressure above 65 atm.

While some fluids used in treatment methods of the invention are borate-crosslinked guar-based fracturing fluids, the fluids may be any crosslinked polymer based fluids, or linear polymer based fluids, used for treating a subterranean formation. The fluids typically include a polymer viscosifying agent and a crosslinker. Non-limiting examples of polymer viscosifiers include guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydropropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG). Cellulose derivatives such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose (CMHEC) may also be used. Any useful polymer may be used in either crosslinked form, or without crosslinker in linear form. Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to be useful as viscosifying agents. Synthetic polymers such as, but not limited to, polyacrylamide and polyacrylate polymers and copolymers are used typically for high-temperature applications. Also, associative polymers for which viscosity properties are enhanced by suitable surfactants and hydrophobically modified polymers can be used, such as cases where a charged polymer in the presence of a surfactant having a charge that is opposite to that of the charged polymer, the surfactant being capable of forming an ion-pair association with the polymer resulting in a hydrophobically modified polymer having a plurality of hydrophobic groups, as described in United States Patent Application Publication 2004209780, which is incorporated by reference herein in its entirety.

When incorporated, the polymer viscosifier may be present at any suitable concentration. In various embodiments hereof, the viscosifying agent can be present in an amount of up to less than about 60 pounds per thousand gallons of liquid phase, or from about 15 to less than about 40 pounds per thousand gallons, from about 15 to about 35 pounds per thousand gallons, about 15 to about 25 pounds per thousand gallons, or even from about 17 to about 22 pounds per thousand gallons. Generally, the viscosifying agent can be present in an amount of from about 1 to less than about 50 pounds per thousand gallons of liquid phase, and the upper limited being less than about 50 pounds per thousand gallons, no greater than 59 pounds per thousand gallons of the liquid phase. In some embodiments, the polymers can be present in an amount of about 20 pounds per thousand gallons. Hydroxypropyl guar, carboxymethyl hydroxypropyl guar, carboxymethyl guar, cationic functional guar, guar or mixtures thereof, are preferred polymers for use herein as a gelling agent. Fluids incorporating polymer viscosifiers may have any suitable viscosity depending upon the particular needs of a given operation. For many operations, the fluids preferably have a viscosity value of about 50 mPa-s or greater at a shear rate of about 100 s⁻¹ at treatment temperature, more preferably about 75 mPa-s or greater at a shear rate of about 100 s⁻¹, and even more preferably about 100 mPa-s or greater. In the case of a slickwater fracturing, also commonly referred to as a water fracture operation, the fluid may have suitably low, but effective, viscosity values, and low polymer loadings, preferably less than about 15 pounds per thousand gallons, more preferably from about 1 to about 10 pounds per thousand gallons.

Fluids used for some embodiments of the invention may be based upon an aqueous or nonaqueous medium. When the fluid is based upon an aqueous medium, the medium may be water or brine. In those embodiments of the invention where the aqueous medium is a brine, the brine is water comprising inorganic salts and/or organic salts. Preferred inorganic salts include alkali metal halides, more preferably potassium chloride. The carrier brine phase may also comprise an organic salt more preferably sodium or potassium formate. Preferred inorganic divalent salts include calcium halides, more preferably calcium chloride or calcium bromide. Sodium bromide, potassium bromide, or cesium bromide may also be used. The salt is chosen for compatibility reasons i.e. where the reservoir drilling fluid used a particular brine phase and the completion/clean up fluid brine phase is chosen to have the same brine phase.

A fiber component may be included in the fluids of the invention to achieve a variety of properties including improving particle suspension, and particle transport capabilities, and gas phase stability. Fibers used may be hydrophilic or hydrophobic in nature, but hydrophilic fibers are preferred. Fibers can be any fibrous material, such as, but not necessarily limited to, natural organic fibers, comminuted plant materials, synthetic polymer fibers (by non-limiting example polyester, polyaramide, polyamide, novoloid or a novoloid-type polymer), fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers, metal fibers, metal filaments, carbon fibers, glass fibers, ceramic fibers, natural polymer fibers, and any mixtures thereof. Particularly useful fibers are polyester fibers coated to be highly hydrophilic, such as, but not limited to, DACRON® polyethylene terephthalate (PET) Fibers available from Invista Corp. Wichita, Kans., USA, 67220. Other examples of useful fibers include, but are not limited to, polylactic acid polyester fibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers, and the like. When used in fluids of the invention, the fiber component may be include at concentrations from about 1 to about 15 grams per liter of the liquid phase of the fluid, preferably the concentration of fibers are from about 2 to about 12 grams per liter of liquid, and more preferably from about 2 to about 10 grams per liter of liquid.

Fluids used in accordance with the invention may also comprise a breaker. The purpose of this component is to “break” or diminish the viscosity of the fluid so that this fluid is more easily recovered from the formation during cleanup. With regard to breaking down viscosity, oxidizers, enzymes, or acids may be used. Breakers reduce the polymer's molecular weight by the action of an acid, an oxidizer, an enzyme, or some combination of these on the polymer itself In the case of borate-crosslinked gels, increasing the pH and therefore increasing the effective concentration of the active crosslinker, the borate anion, reversibly create the borate crosslinks. Lowering the pH can just as easily eliminate the borate/polymer bonds. At a high pH above 8, the borate ion exists and is available to crosslink and cause gelling. At lower pH, the borate is tied up by hydrogen and is not available for crosslinking, thus gelation caused by borate ion is reversible.

Fluids used in methods of the invention may further contain other additives and chemicals that are known to be commonly used in oilfield applications by those skilled in the art. These include, but are not necessarily limited to, materials such as surfactants, foaming agents, crosslinking delay agent, breaker delay agents, particles, proppants, gas component, breaker aids, oxygen scavengers, alcohols, scale inhibitors, corrosion inhibitors, fluid-loss additives, bactericides, friction reducers, latexes, emulsions, emulsifiers, and the like.

There are many different types of fluid systems employed for these types of treatments including plain water, water with friction reducer (drag reduction for pipe flow), water gelled with natural polymers (guar, guar derivatives), synthetic polymers (polyacrylamide), biopolymers (xanthan) and other means. In any of these systems the aqueous gelled fluid can additionally be crosslinked in order to enhance the viscosity further. Crosslinkers such as borate, titanium, zirconium, aluminum and others have been used for this purpose. The based fluids can also be hydrocarbon. As well, formulations can be prepared as emulsions, dispersions and other types of systems in order to provide better performance for the many types of formations and wellbore conditions that can be encountered in various parts of the world.

Methods of the invention may also be used to for real-time QA/QC of the fluids, thus making possible to adjust the fluid components during an operation to achieve a further optimized fluid and treatment schedule. The rheology model can be used to further extrapolate monitored surface characteristics such as viscosity, pumping rate, temperature, polymer concentration, crosslinker concentration, breaker concentration to bottomhole conditions.

Embodiments of the invention relate to a method and apparatus for treating a subterranean formation comprising designing a treatment that comprises a liquid, wherein the design comprises a pressure influence on a viscosity of the liquid and performing the treatment. Embodiments of the invention relate to a method and apparatus for exposing a subterranean formation to a liquid comprising forming a liquid comprising a polymer and a crosslinker, pumping the liquid into the subterranean formation wherein the forming the liquid comprises selecting the composition of the liquid in response to a pressure and temperature of the subterranean formation and experimentally derived behavior of the polymer and the crosslinker at the pressure, temperature, and pH of the subterranean formation.

EXAMPLES

The following example illustrates the methods of the invention, as described in the preferred embodiments.

During a hydraulic fracturing pumping operation, the pressure the fluid experiences while in the subterranean formation can be quite high. These pressures might range from about 2,000 to over 20,000 psi (13.8-138 megapascals). As the laboratory equipment defined for testing completions fluids under ISO-13503-1 is not capable of confining the fluid under these pressures, alternative viscometers were employed to develop a set of data from which to model the pressure effect. The primary of these was a model M7500 manufactured by Grace Instrument. This rheometer, similar to those described in the ISO standard, has concentric cylinder geometry. The dimensions of the inner cyclinder (non-rotating) are 3.45 cm diameter with a height of 3.80 cm. The rotating cup has an internal diameter of 3.68 cm.

As the root cause of the loss of viscosity due to increased hydrostatic pressure is not known, modeling the effect is, by necessity, empirical. For this purpose, a large number of tests were conducted with varying borate gel compositions, temperatures and pressures. An example of a set of tests for a single composition is shown in FIG. 4. Each test for this series was conducted with a new sample at a single temperature, and during the test, the viscosity was continuously measured at increasing pressure, successively raising the pressure from 2,000 psi to 20,000 psi in steps of 2,000 psi.

From a large collection of such data, a fit to an equation that includes polymer concentration, boron concentration, pH, temperature and pressure was made.

Examples of applying that fit are shown in FIGS. 5 and 6.

These examples illustrate that an effective rheology model for borate crosslinked guar-based fracturing fluids exists. The model enables a prediction of the viscosity during a fracturing job.

FIG. 7 is a three dimensional plot of estimated viscosity for a fluid composition over a range of pressure and fluid temperature.

The methods and compositions described herein may be used in a variety of oil field applications such as fracturing, gravel packing, or reservoir treating or work over or clean out fluids.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. For example, even though borate crosslinked polymer gels are the only completion fluids identified to date that have a significant viscosity response to pressure, it is envisioned that other fluids may be identified whose rheology is substantially changed by pressure. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the protection sought herein is as set forth in the claims below. 

1. A method for treating a subterranean formation, comprising: designing a treatment that comprises a composition, wherein the design comprises a pressure influence on a viscosity of the composition; and performing the treatment, wherein the composition is not an energized fluid.
 2. The method of claim 1, wherein the viscosity is at least partially estimated based on experimental rheological data collected at pressures below about 500 psi.
 3. The method of claim 1, wherein the viscosity is at least partially estimated based on experimental rheological data collected at a pressure that is about 1 to about 2,000 atm.
 4. The method of claim 1, wherein the viscosity is at least partially estimated based on shear rate of the liquid.
 5. The method of claim 1, wherein the viscosity is at least partially estimated based on temperature, pH, polymer concentration, and/or crosslinker concentration of the liquid.
 6. The method of claim 1, wherein the composition comprises a polymer.
 7. The method of claim 1, wherein the composition comprises a crosslinker.
 8. The method of claim 7, wherein the crosslinker comprises boron.
 9. The method of claim 1, wherein the pressure influence occurs at a pressure above 65 atm.
 10. A method for exposing a subterranean formation to a composition, comprising: forming a composition comprising a polymer and a crosslinker; pumping the composition into the subterranean formation; wherein the forming the composition comprises selecting the composition components in response to a pressure and temperature of the subterranean formation and experimentally derived behavior of the polymer and the crosslinker at the pressure, temperature, and pH of the subterranean formation.
 11. The method of claim 10, wherein the experimentally derived behavior of the polymer and the crosslinker is at least partially estimated based on experimental data at the pressure and temperature of the subterranean formation.
 12. The method of claim 11, wherein the experimental data is collected at pressure that is about 1 to about 2000 atm.
 13. The method of claim 10, wherein the experimentally derived behavior of the polymer and the crosslinker is at least partially estimated based on shear rate of the liquid.
 14. The method of claim 10, wherein the experimentally derived behavior of the polymer and the crosslinker is at least partially estimated based on temperature, pH, polymer concentration, and/or crosslinker concentration of the liquid.
 15. The method of claim 10, wherein the crosslinker comprises boron.
 16. The method of claim 10, wherein the pressure experienced by the composition being pumped into the subterranean formation is above 65 atm.
 17. The method of claim 10, wherein the forming the composition comprises estimating the viscosity of the liquid.
 18. The method of claim 17, wherein the estimating the viscosity comprises using the experimentally derived behavior of the polymer and the crosslinker at the pressure of the subterranean formation.
 19. The method of claim 17, wherein the estimating the viscosity comprises using the pressure, temperature, of the subterranean formation and experimentally derived behavior of the polymer and the crosslinker at the pressure, temperature, of the subterranean formation.
 20. A method for exposing a subterranean formation to a composition, comprising: forming a composition comprising a polymer and a crosslinker; pumping the composition into the subterranean formation; wherein the composition viscosity is estimated using the following formula, ${{Viscosity}({cP})} = \frac{47\text{,}880k_{a}^{\prime}}{\gamma^{({1 - n^{\prime}})}}$ wherein γ is the shear stress, and wherein k_(a)′ and/or n′ is a function of pressure, and wherein the forming the composition comprises using the estimated composition viscosity. 